Steam turbine generator speed control - clarification

M

Thread Starter

Mikas

Hello to all,

I need clarification about a couple of things regarding turbogenerator's speed control.
Can you confirm the following:

1. When generator is not connected to the grig, when openning steam regulating valves and allowing more steam to turbine, turbine will rotate faster, right?

2. Generator is mechanicaly coupled with the turbine and it always rotates same speed as turbine.

3. When generator is in parallel with the grid, it cannot rotate faster or slower then 50Hz (suppose for Europe) or 3000 rpm (2 pole machine), or in another way, it will rotate the same speed as grid's frequency (for example 49.98 Hz).

4. When generator is synchronized with the grid, adjusting steam control valves cannot change the speed of the turbine/generator and it will change only output power.

I'm looking forward to your comments.
Thank you very much.
 
Mikas,

You have it all correct.

1) When the unit is not connected to a grid (particularly a large, or infinite, grid) increasing the energy being admitted to the prime mover will cause the prime mover to increase speed.

When the unit is connected to a grid, increasing the energy being admitted to the prime mover will NOT result in a speed increase. It WILL result in an increase in the amperage of the generator. In other words, the power output of the generator will increase. The extra torque which would cause the unit to increase its speed when not connected to the grid gets converted by the generator into additional power output (amps).

2) If the prime mover and generator are directly coupled, in other words, there is no reduction gear or speed increaser between the prime mover and the generator, the prime mover and the generator will turn at the same speed as the generator.

Even if there is some gear box (reduction or speed increaser), the speed of the prime mover is still directly proportional to the speed of the generator rotor. And the speed of the generator rotor is directly proportional to the frequency of the grid to which the generator is connected.

As has been noted elsewhere on control.com, the frequency of a generator is directly proportional to the product of the number of poles of the generator times the speed of the rotor (in RPM), divided by 120: F = (P*N)/120. If a grid is operating at 50 Hz and the generator connected to the grid has two poles, the speed of the generator rotor will be 3000 RPM (N = (120*50)/2).

3) AC generators are usually synchronous generators. Synchronous means they are locked in synchronism with the frequency of the grid to which they are connected, especially if the grid is very large, or, infinite. Suppose a 60 MW steam turbine is connected in parallel with other generators on a grid with a total output of 6,000 MW. The little 60 MW steam turbine isn't going to make all the other turbines speed up or slow down detectably as the prime mover's energy is increased or decreased--there's just too much inertia to overcome.

Also, there should be operators and control systems somewhere on the grid which would decrease the load of one or more units to maintain the grid frequency at rated. As units are loaded by their operators they actually accept some of the load from the grid. If enough units are loaded without some units being unloaded equally, the grid frequency will begin to increase.

4) See 1, 2, and 3 above.

But, you've got it!
 
Control systems have a controlled variable and a manipulated variable. If a control system detects no change in the controlled variable, the system has no reason to change the manipulated variable.

If a synchronized generator is asked to adjust load, torque is removed or applied to the prime mover. If these changes in speed are "undetectable", the control system has no reason to increase or decrease power input. The changes are infinitely small, yet must exist for the control system to respond. I will concede that multiple things are happening in one instant of time, but a detectable change is occuring.

Although the hugh power sink in a large grid seem to minimize or absorb changes, measureable changes are occuring. If not the manipulated variables would not change.

The large "infinite bus", whether controlled by human or non-human controls systems must be able to "detect" these incredibly small changes or no reason would exist for the control systems to change their manipulated variables (i.e. other generator sets on the grid.) and maintain this dynamic and delicate balance of frequency and voltage.

I may be totally wrong. I have found that on the generator sets that I have encountered; Speed is the controlled variable and steam or fuel input to the turbine is the manipulated variable. Therefore speed must change to induce a change in steam/fuel imput.

I welcome all feedback on why I am wrong.

CTTech
 
Thank you very much for your answer.
There are more I'd like to learn.

1. What will happen with grid's frequency if one large transmission tower fail? In that case generators stays without load and I'm very interesting how frequency is changed!?!

2. Since increasing in steam flow in turbine will cause output power to increase and increasing in power is because increasing of generator current, I'd like to know what is happening with the voltage.

3. I know that reactive power is somehow related to generator's voltage and excitation, but that is very blur to me. If possible can you explain this?

Thank you very much!
 
B

Bruce Durdle

Lets go back to basics ... A turbine-generator set obeys an energy balance law. Energy in = energy out + change in stored energy. Or power in = power out + rate of change of stored energy.

Power in is found by multiplying the steam flow by the steam enthalpy (- the cooling water flow * increase in CW energy) (- a few other terms that are more or less constant). Power out is the electrical load on the generator. Stored energy in the machine is kinetic energy of rotation and proportional to the square of RPM. If the load is increased above the power in, the machine will slow down.

A power system is an energy balance on a very large scale. The energy in is the mechanical energy applied to all the turbines. The energy out is the sum of the demand of all the light bulbs, wall warts, TV sets, and electric motors connected to the system. When you turn on a light bulb, all the connected rotating machines will slow down. Somewhere on the system is a generator that will sense the drop in speed and increase generation.

On a large interconnected system such as that in North America, this speed drop is infinitesimal - but it still happens. On a smaller system such as we have here in NZ, frequency excursions due to sudden load changes are a fact of life - a hiccup on the DC link connecting the 2 islands can cause a 1 or 2 % frequency drop in 1 or 2 seconds.

On a steam turbine connected to a grid, a shortfall between power in and power out could occur if there is a small drop in steam pressure or temperature, as well as a load change. This will cause the rotating parts to slow down. As a result, the internal angle between the rotor poles and the magnetic field set up by the stator currents will fall, and the exported electrical power will drop. This restores the balance. The speed excursion will be very short-lived and will probably not affect a governor.

In older systems, the set-point for a governor was referred to as the "speeder gear". Prior to synchronising, a change in the setting for the speeder gear resulted in a speed change. After synchronising, the same change would give an increase in power with no obvious change in speed. With electronic governors, the control strategy can be a lot more complicated and perhaps needs to be.

On one plant I have worked on we had a small 2.5 MW gas turbine. The governor system was capable of reacting very quickly to the above-mentioned frequency dips, and would increase generation in response - sometimes to well above the nameplate rating (I have seen the analogue power indication at more than 3.5 MW on occasion). An electronic power limit would have been quite useful in that case.

So CTTech is right - speed is the major controlled variable, and changes in speed act to change the governor valves. The system is also self-regulating in that the electrical power out changes with machine angle.

Bruce.
 
1. Hopefully enough reliability is built into the system to prevent power loss to customers. If so, power system operators will only record a short lived frequency excursion and power will be rerouted. Crews to repair the damage to the tower will be dispatched.

If this is not the case, someone/something/somewhere will be without power until repairs can be made.

2/3. Most large loads on the power system are inductive (induction motors). An area that produces power must be able to react to the inductive load. They do this by producing VARs(Volt Amp Reactive power). Additional information on VARs is available on the internet.

Capacitance can also be added near a large inductive load reducing the need for VARs. VARs and MW output are connected.

VARs reduce the amount of megawatts a generator can produce, therefore a cost is incurred for the production of VARs. The power producer for an area must monitor loads through the different seasons and find a balance. The addition of capacitance in certain areas versus the cost of producings VARs and the resultant loss of system production capacity.
 
P
I disagree with both CCTech's 23-Jun (02:29) and Bruce Durdle's 23-Jun (14:02) comments stating that the major controlled variable is speed.

I believe we can all agree that power-demand (kW) is provided by the prime mover. Furthermore, we can agree that any power demand change will cause the turbine's Speed Regulator, the Turbine Governor Control (TGC), to intervene, thus correcting deviations. But, the response is relatively slow. So slow in fact, that its impact on system stability is ignored! (Just think of the original TGC, the Watt rotating-ball governor)

But, now consider the case when load power-factor changes, i.e., power-demand remains constant but the load's power-factor, or as is said, reactive-power (kVAr) changes. Does the speed change? No! Why not? Because reactive-power is not real-power! So what happens? Of course, the generator's current output changes! That change, then results in a change of the generator's terminal voltage. What detects that change: the AVR!

Thus, the voltage regulator, or in today's jargon, the AVR, changes the generator's field-excitation to correct the terminal voltage. (The 'A' in AVR, of course eliminated the need for an operator to keep an eye on the volt-meter!) The AVR, while it can't supersede the TGC, certainly complements it. It allows quicker response to output requirements. There shouldn't be any doubt about the improvement in dynamic response that today's computer-generated transfer-function models have made to system stability and transient recovery! But, the real key is the AVR's ability to instantly detect electrical parameter change, not the TGC's ability to control turbine speed!

Phil Corso, PE ([email protected])
 
Thanks to Mr. Durdle for sparking a return to basics. There's nothing more enlightening than beginning at the beginning. Unfortunately, we can't discuss the theory of magnetism and amperes and voltage and current, and specifically, of alternating current and voltage; it's presumed we all understand those basics or can look them up. But, we'll venture again into the breach.

Synchronism: to occur at the same interval or frequency. Synchronous generator: a device, usually with a rotating electrical field that, when operated properly (as per Mr. Corso) in parallel with other electrical generators, will spin at a speed that is directly proportional to the frequency of the alternating current on the grid.

From other posts, that speed is N = (120 * F)/P. N is the speed of the rotor, in RPM; F is the frequency of the AC system to which the synchronous generator is connected, in Hz; P is the number of poles of the electrical field; 120 is a number which allows for conversion between Hz (cycles per second) and RPM (revolutions per minute).

When a synchronous generator is connected in parallel with other synchronous generators, an electrical magnetic field is created on the stator, actually three electrical magnetic fields since most synchronous generators are three-phase machines. Because of the alternating nature of an AC electrical system, the magnetic fields created on the stator appear to rotate around the stator.

The rotating electrical field of the synchronous generator is locked in to synchronism with the rotating electrical fields of the stator and can not spin any faster or slower than the rotating electrical fields of the stator. And that speed is defined by the formula above.

When a synchronous generator is started and accelerated to synchronous speed in preparation for connecting the generator to a grid in parallel with other generators, any change in energy to the prime mover results in a change in speed of the rotor of the generator. That change in speed will result in a change of the frequency of the synchronous generator by solving the formula above for frequency: F = (P*N)/120, which is the same formula above, just solved for frequency.

Once the synchronous generator is synchronized (there's that word again!) to the grid with other generators, it's speed is fixed by the frequency of the grid. Any change in energy to the prime mover will result in a change in the amount of amperes flowing in the stator of the synchronous generator because. And the power produced by a synchronous generator is a function of the number of amps flowing in the stator of the generator.

This relationship between frequency and speed is one of the reasons why a synchronous generator must be synchronized with an electrical grid when it is being connected to an electrical grid. The frequency of the synchronous generator being connected to the grid must be made nearly equal to the grid's frequency before the generator breaker is closed for a smooth and stable breaker closure. The speed of the rotating magnetic field is directly proportional to the frequency of the synchronous generator, so the prime mover's speed is adjusted to make the frequency of the synchronous generator nearly equal to the grid's frequency.

Once the generator breaker is closed, any change in energy being admitted to the prime mover will result in a change in the torque being applied to the synchronous generator. Because the synchronous generator is now controlling the speed of the unit (the prime mover and the synchronous generator), the change in torque does not result in a change in speed of the unit, it results in a change in the amperes flowing in the stator of the generator.

So, there's a certain amount of energy that's required to make the synchronous generator rotor spin at a speed that makes the frequency of the generator equal to the frequency of the grid to which is is connected. This is the energy required to make the synchronous generator spin at synchronous speed.

Once the synchronous generator is connected to a grid with other electrical generators, an increase in energy being admitted to the prime mover which would tend to increase the speed of the unit results in an increase of the electrical power of the generator causing more amperes to flow in the stator of the generator, but not an increase in speed of the unit.

If the energy being admitted to the prime mover driving a synchronous generator connected to a grid with other electrical generators is less than the energy required to keep the generator rotor spinning at a speed sufficient to keep the generator frequency equal to the grid frequency the generator will become a motor and spin the prime mover at a speed which is directly proportional to the grid frequency. If the energy being admitted to the prime mover were shut off and the breaker remained closed, the unit would continue to spin at synchronous speed, as long as the excitation being applied to the synchronous generator rotor remained operational (in deference to Mr. Corso, which is why we must keep making reference to synchronous generators being operated as synchronous generators, even though he has provided no details about how long the synchronous generator which was operated asynchronously lasted when being operated without excitation or for how long it operated asynchron
ously).

To understand AC, alternating current, electrical power generation one must understand the machines used to generate electrical power and those are usually synchronous machines. When operated as designed when connected to an electrical grid with other generators, synchronous generators and the prime movers which are usually directly coupled to the generator rotors can spin no faster nor any slower than the speed defined by the formula above.

Any change in the torque being applied to the generator by the prime mover will result in a change in the amperes flowing in the generator stator. Increasing the torque above that required to maintain synchronous speed and frequency will result in amperes which can be used to power loads connected to the grid. These amperes are generally considered to "flow" out of the generator.

Decreasing the torque below that required to maintain synchronous speed and frequency will result in amperes flowing in the generator stator which will cause the generator to become a motor and keep the rotor and the prime mover turning at synchronous speed and frequency. In this case, the amperes are considered to "flow" into the generator, "motorizing" the generator.

The only difference between a synchronous motor and a synchronous generator is the direction of current flow, or, from a different point of reference, the direction of torque flow. Torque exceeding that required to maintain synchronous speed will cause the electrical machine to become a generator. Torque less than that required to maintain synchronous speed will cause the machine to become a motor. Amps will flow out of a synchronous electrical machine which has an excess of torque being applied to it, excess meaning more than required to maintain synchronous speed. Amps will flow into a synchronous electrical machine which has a deficiency of torque being applied to it, meaning less torque than required to maintain synchronous speed.

But in no case will the speed of a synchronous electrical machine be more or less than the synchronous speed, which is directly proportional to the frequency of the AC grid to which it is connected regardless of whether it is a motor or a generator.

The power, watts, produced by a synchronous machine are a function of the torque applied to the machine by the prime mover.

Amazingly enough, reactive power, or VArs, is very similar to watts. Increasing excitation above that required to maintain the generator terminal voltage equal to the voltage of the grid to which the synchronous generator is connected will cause VArs to "flow" out of the generator. Decreasing the excitation below that required to maintain the generator terminal voltage equal to the voltage of the grid to which the synchronous generator is connected will result in VArs "flowing" into the generator.

(This ought to get a response from Mr. Corso!)
 
From previous posts about droop speed control, which is how most prime movers are operated when the synchronous generators they are driving are connected in parallel with other generators on a grid, the frequency of a synchronous generator is defined by the formula F = (P * N) / 120. F is frequency, in Hz; p is the number of poles of the synchronous generator; N is the speed of the synchronous generator rotor to which the prime mover is typically coupled; and 120 is a constant which is used to convert all sorts of things (radians, and RPM to seconds (Hz), etc.).

The formula can be solved for speed: N = (120 * F) / P. For a two-pole synchronous generator connected to a 60 Hz grid, the rotor will spin at 3600 RPM. For a two-pole synchronous generator connected to a 50 Hz grid, the rotor will spin at 3000 RPM.

Most prime movers are connected directly to the synchronous generator rotor either though a single load coupling or through a reduction gear; very few couplings are variable speed couplings.

Consider a 40 MW turbine-generator connecting to a 6,000 MW grid. It's impossible for that 40 MW generator's prime mover to increase the speed of all the other generators on the grid by any appreciable amount. The 40 MW unit's synchronous generator is locked into the same frequency as all the other generators on the grid, and because the prime mover is directly coupled to the synchronous generator its speed is directly proportional to the generator rotor's speed which is a function of the frequency.

It's a pretty straightforward formula, and when a synchronous generator is connected in parallel with other synchronous generators, no single synchronous generator can run faster or slower than any other synchronous generator. (That's kind of the definition of synchronism: everything is occuring at the same interval or "frequency", no pun intended.)

If the prime mover could be disconnected from the synchronous generator rotor while the generator was still connected to the grid, the synchronous generator rotor would continue to spin at synchronous speed, no faster and no slower. In fact, if the energy being admitted to the prime mover is cut off and the synchronous generator remained connected to the grid, the generator and the prime mover will remain at synchronous speed.

The next time the units at your site are connected to the grid, check the speed of the prime movers--if the prime movers are directly coupled to the synchronous generators, the speed of the prime mover is fixed by the generator frequency when connected to the grid.

No matter how much torque is applied to the generator, as long as the torque doesn't exceed the rating of the generator, the speed of the synchronous generator rotor will be fixed by the frequency of the grid to which it is connected. The torque--which would increase the speed of the rotor if the generator were not connected to the grid--gets converted to amps by the generator. Amps that power devices connected to the grid.

Droop speed control changes the turbine speed reference--it doesn't actually change the turbine speed when the synchronous generator being driven by the prime mover is connected to a grid. Droop speed control is straight proportional speed control. If there is an error between the prime mover speed reference and the actual speed there is NOTHING in the control system which drives the error to zero.

So, when a prime mover is being commanded to operate at 102.4% of rated speed, it can only operate at the speed which is directly proportional to the frequency of the synchronous generator to which it is directly coupled. And if the generator is connected to a grid in parallel with other generators, its frequency is fixed by the frequency of the grid. The frequency of the grid is the one thing in a power system that's supposed to be fixed and constant. That is, unless you're in India where the grid frequency is ANYTHING but constant. Voltage can vary a little, but frequency is supposed to be constant.

If the frequency can't change, the speed of the rotor can't change. If the speed of the rotor can't change, the speed of the prime mover can't change since the prime mover is usually directly coupled to the rotor, sometimes through a reduction gear, but that's not variable.

Droop speed control uses the error between the speed reference and the actual speed to increase or decrease the amount of energy being admitted to the prime mover. As the prime mover speed reference is increased, but the actual speed is constant, fixed by the frequency of the generator which is connected to the grid, the error between the reference and the actual increases--and the energy admitted to the prime mover increases. The opposite happens with the speed reference is decreased.

It is the fact that the actual speed of the prime mover is constant and the only variable which is changing is the speed reference that allows prime movers to share load with other prime movers and their generators on an electrical grid when prime movers are operated in droop speed control.

This is a pretty common misconception. Most operators and many technicians all see the speed of the prime mover increase and decrease during startup and shutdown and just assume that the speed changes when the synchronous generator is connected to the grid. But it can't.

So, you, too, CTTech, are correct when you say "speed is the controlled variable and fuel is the manipulated variable". But, it's the error between actual speed which should be constant and speed reference. It's the magnitude of the error which manipulates the fuel. The thing is: the actual speed is controlled by the grid via the frequency of the generator and the variable is the speed reference.

And now for the disclaimer: The above applies to synchronous generators which are not being operated asynchronously. (Even though asynchronous operation of a synchronous generator will usually result in an overheated rotor, and probably a pretty severe generator failure.)
 
I concur with Mr. Corso to a degree. A GE EX2000 Excitation drive is so fast in response time that an additional feedback signal had to be added to stabilize the drive. The feedback is speed.

I merely wanted to point out that to fully understand this delicate and dynamic balance; one must first learn the basics. Generator speed and generator frequency are directly related and this cannot be ignored. To infere that generator speed is NOT changing while synchronized is ignoring this relationship.

Once the basics are learned, one can investigate the many other things that are happening in the same instant of time to stabilize yet increase response time of the delicate energy balance.

Best regards,
CTTech
 
B
Since we are getting into the maths... Power transfer through a reactive transmission line depends on the products of the two terminal voltages, is inversely proportional to the reactance, and is proportional to the sine of the power angle or phase angle difference (delta) between the voltages. This is how power systems fall apart if a line is overloaded - when delta approaches 90 deg, sine delta reaches a maximum. If a generator is on the end of a line with significant reactance, and power is increased too far, delta exceeds 90 degrees and the transmitted power falls - the machine loses synchronism and trips - power available to the rest of the system falls - more lines are overloaded - and the lights go out.

While the machines on a system are all rotating at the same electrical speed they are not all aligned - the rotors of lightly-loaded machines will be more or less in step with each other, but the rotors of heavily-loaded machines will lag by somewhere about 60 deg. Sudden load changes will change this angle which will cause a very short-lived apparent speed change. In CSA's example of a 40 MW generator on a 6000 MW system, the frequency change needed to accommodate the loss of the 40 MW set is .013 Hz on a 50 Hz system, .016 Hz on a 60 Hz one, if all machines have a droop setting of 4%. This may or may not be appreciable. A good time to watch for frequency changes on a power system is between 6 am and 9 am - when loads are increasing and generation is increasing to match.

Bruce
 
1. The amount of generation must always equal the load in order for the frequency to be stable. If a transmission tower falls and some generation is removed from the grid unless there is sufficient capacity of the remaining generators, the grid frequency is going to decrease if the load exceeds the generation. Sufficient generation capacity means enough of the remaining generators and their prime movers which are still connected to the grid are running at part load and not at full rated power output and can be loaded to make up the difference of what was lost when the tower fell.

If a large block of load is suddenly removed from the grid because of the failure of a circuit breaker in a switchyard the grid frequency will increase unless one or more units have the energy admitted to the prime movers reduced. If the generation exceeds the load, the grid frequency will increase.

2. When torque input to the synchronous generator increases, the amperage flowing in the stator windings of the generator increases. This causes the strength of the magnetic fields of the stator to increase, which causes the field of the generator rotor to shrink or collapse. If nothing is done and the torque input to the generator continues to increase, the generator terminal voltage would tend to decrease. This is commonly referred to armature reaction.

In order to maintain VAr "flow" or power factor at a desired setpoint when manually controlling excitation while loading a unit (increasing the energy into the prime mover), it is necessary to increase excitation to counter the armature reaction.

Conversely, when unloading a unit (reducing the energy admitted to the prime mover) and controlling excitation manually it is necessary to reduce excitation as the unit is unloaded to maintain the desired VAr or power factor setpoint.

Some machines have VAr and/or power factor control features to automatically adjust excitation to control a VAr or power factor setpoint.

3. When a synchronous generator is not connected to the grid but is running at rated speed any increase in excitation will result in an increase in generator terminal voltage. Conversely, any decrease in excitation will cause the generator terminal voltage to decrease. Synchronous generator terminal voltage is directly proportional to the speed of the generator rotor (which is held fixed when connected to the grid) and excitation.

If a synchronous generator is connected to a grid with its terminal voltage equal to the grid voltage, the power factor will be unity, 1.0, and there will be zero VArs leading or lagging. Once connected to the grid, if the excitation is increased the power factor will shift to less than 1.0 lagging, and VArs will "flow out" of the synchronous generator on to the grid. So, that in the same way an increase in torque would tend to increase speed, an increase in excitation would tend to increase generator terminal voltage but the power factor and the VAr flow changes.

Usually, an increase in excitation will cause the synchronous generator terminal voltage to increase slightly when connected to the grid depending on grid conditions and other system factors, but it would not increase by the same amount as if the generator were not synchronized to the grid. Increasing excitation above that required to maintain generator terminal voltage equal to system grid voltage is sometimes referred to as over-excitation and results in the generator trying to boost the system voltage.

Decreasing excitation below that required to maintain synchronous generator terminal voltage equal to grid voltage is sometimes referred to as under-excitation and results in the generator trying to buck the system. When excitation is reduced below that required to maintain synchronous generator terminal voltage equal to grid voltage, the power factor shifts to leading and less than 1.0 and VArs "flow into" the generator.

Whether they actually flow into or out of the generator seems to have been contended before on this site. Convention talks about VArs flowing into and out of the generator. Some people dispute whether or not amperes flow in a generator stator on an AC system, since it is an alternating current. Others say current flows from positive to negative in a DC circuit, while still others say it flows from negative to positive.

It all depends on one's point of reference. And if VArs are considered as being consumed and produced as Watts are (and they are--it's just that most people never see a VAr-hour meter, but they do exist!) then synchronous machines produce VArs when they are over-excited and consume VArs when they are under-excited. It's not possible to control VAr consumption of machines like induction motors and transformers like Watt consumption is controlled; the VAr consumption is a function of how equipment and machines are built. But if someone doesn't produce VArs to at least partially offset the consumption of VArs, the lights are going to dim and maybe even go out.

And the maths are going to start coming now. Hopefully not, because we're just talking principles in general terms for operators and technicians, not scientists and engineers. The maths can be found in any text or reference book, but they rarely discuss principles and unless one takes a long time to understand the maths then it just confuses things for beginners--and we were all beginners once.

The maths are just proofs of principles, and we need to understand the principles to be good operators and technicians. To predict or model we need to understand the maths. But I've run into more than one person who can cite the maths, but can't explain what's really happening. Vectors and trigonometry and calculus are all wonderful things to engineers and scientists but just add to the confusion of operators and technicians. If they want to look up the maths and the formulae, they can. This seems to be a site where people can ask basic questions and learn and get more information if they desire.
 
Mr. Tesla and Mr. Westinghouse started out small. They had no idea how far this would go. I am sure that frequency was "something to watch" on their first outing.

I had no desire to overwelm anyone. For the "newbies": Study Tesla and the induction motor and AC. Learn the basics.

CTTech
 
1) Why do we want the VArs to flow out of the generator always?

2) If every generator is forcing VArs out, trying to maintain a lagging pf, then is there someone (a generator) out there who's allowing those forced out VArs, into them?

3) When you specifically say Synchronous Generator, does it also mean that there are Asynchronous Generators too? Or it only means that a generator automatically becomes synchronous (or can we say, synchronized?) when it's connected to an infinite bus because it's too small to effect a change on a large system and hence has to behave like the grid?

4) Is terminal voltage only due to AVR excitation? Will the torque (and not the speed) of the prime mover have no role to play in determining the terminal voltage?

5) When the generator and prime-mover are spinning in synch with the grid, does an extra fuel into the prime mover also increase the mass flow of air through the prime-mover (a single shaft turbine), if the axial compressor air inlet vanes are not modulating with load?

thanks.
 
1) Because the majority of synchronous generators are not made to run in an underexcited (leading power factor) mode. Refer to the reactive capability curve of the generator for specifics of how a generator may be operated.

Excessively reducing excitation to put the generator in a leading power factor reduces the synchronous generator field strength, increasing the possiblity of allowing the torque being input to the rotor to overcome the magnetic attraction between the rotor and the stator, "slipping a pole" which is very catastrophic. There are also problems with generator heating when operating in an underexcited condition.

2) Lagging VArs feed a lagging load. The majority of reactive loads on most grids are inductive: induction (asynchronous) motors and transformers (yes, transformers are a inductive load on the system). The effect of a lagging load is to shift the voltage and current sine waves out of phase with each other. By providing lagging VArs, the voltage and current sine waves are shifted back towards each other.

3) Yes, there are induction (asynchronous) generators, though they are usually small machines (small hydro turbine-generator or small wind turbine-generators).

4) Synchronous generator terminal voltage is a function of two variables: speed and excitation. Since the speed of a synchronous generator is usually constant, the way to change terminal voltage is to change excitation.

As was said previously, armature reaction affects terminal voltage. Increasing armature current reduces generator terminal voltage due to armature reaction.

5) When fuel is burned in the combustor of a gas turbine, the pressure in the combustor increases. Axial compressors don't behave as people expect them to; when the "back pressure" in the combustor increases due to the addition of more fuel, the axial compressor discharge pressure increases. So, even though the air flow is not changing because the speed is not changing (for a single-shaft gas turbine) and the variable inlet guide vanes are stationary, the axial compressor discharge pressure will increase as fuel is increased.

Extra fuel does increase the total mass flow--but not the mass flow of air, just the axial compressor discharge pressure.
 
Extra fuel does increase the total mass flow--but not the mass flow of air, just the axial compressor discharge pressure.

1) What happens to the exhaust temperature?

2) If the exhaust temperature increases then the guide vanes will open to maintain the exhaust temperature and otherwards TTXM will go higher. Is it right? Can you please explain?
 
From many other posts on this site, as a GE-design heavy duty gas turbine is loaded the exhaust temperature will increase. As the unit is loaded to Base Load, the IGVs of more recent units will modulate open at various points during the loading depending on the mode of IGV control.

The early versions of IGV control for most simple cycle applications kept the IGVs at the minimum modulating position, usually 57 degrees, until the exhaust temperature reached approximately 900 F. Then as load (fuel flow) was increased the IGVs were opened to maintain 900 F until they were fully open, usually 84 degrees. At that point, any increase in load (fuel flow) would cause the exhaust temperature to increase until the unit reached Base Load exhaust temperature control.

Combined-cycle applications can improve the over-all plant efficiency by maximizing gas turbine exhaust temperature during low load operation. So, the IGVs were usually held at the minimum modulating position until the exhaust temperature was equal to or slightly less than the exhaust temperature control reference as the unit was loaded.

When the exhaust temperature at part load reached the exhaust temperature control reference, the IGVs were opened to keep the exhaust temperature at or near the exhaust temperature control reference until they were fully opened. At that point the unit was usually at or near Base Load anyway.

However, when the unit is operating on Base Load, an increase in load results when air flow increases (usually due to a decrease in compressor inlet temperature) which cause CPD to increase. The increased CPD would tend to cause both the firing temperature and the exhaust temperature to decrease if the fuel were held constant, but the Exhaust Temp Control curve allows a little extra fuel to be burned because it is really trying to maintain a constant firing temperature.

The confusing part of this for most people is that even though fuel flow and load increase slightly, exhaust temperature decreases. The exhaust temperature decreases because the net effect of the increased air flow and CPD causes the exhaust temperature to decrease because the majority of the increased air flow is not used in the combustion of the increased gas fuel flow.

The exhaust temperature control curve has a negative slope, so for an increase in CPD, the resultant exhaust temperature reference will decrease. CPD increases as load increases while operating on exhaust temperature control. This just drives some people crazy because it seems to be opposite of what would be expected.

The exhaust temp control curve represents a constant firing temperature--which is not being monitored. It's being predicted by the exhaust temperature control curve based on two parameters, CPD and exhaust temperature. If we could measure the firing temperature while operating on Base Load, it would be constant at any point on the sloped portion of the curve--regardless of CPD or exhaust temperature and fuel flow.

That's what the sloped line represents: constant firing temperature. Exhaust temperature and CPD will vary while operating on Base Load, but the firing temperature will not. And that's what Base Load is all about: maintaining constant firing temperature and maximizing power output under changing ambient conditions while optimizing the parts life of the gas turbine.

So, the answers to your questions depend on what type of IGV control is being used, and whether or not the unit is operating at Base Load. It's not a simple answer, but in general as units are loaded the exhaust temperature will increase as CPD increases until the unit reaches Base Load. At that point the unit cannot be loaded any further by the operator. Changes in ambient temperature will cause load to increase or decrease slightly while on Base Load, but the exhaust temperature will respond opposite to what is expected while on exhaust temp control. It drives most people crazy, but that's the way it works.

And, to CTTech's point, we are a little off-topic here. But, a question is a question, and it deserves an answer. One will find all kinds of drift on topics on control.com.
 
By the way, there is a pretty cool little real-time "ticker" application on http://www.ucte.org of the European grid frequency.

These are the little disturbances that the system operators have to respond to during the day. Check it out in the middle of the evening, and in the middle of the morning, and in the middle of the day, and on weekends at various times during the day--but check it out!

Note the resolution of the graph. It's pretty "fine", like thousandths of a Hz. That's why it can sometimes look pretty ragged.
 
I understand that synchronous generators and the prime movers which are usually directly coupled to the generator rotors can spin no faster nor any slower than the frequency (speed) of the main power grid they are connected to. However, how does the amperage in the stator increase/decrease based on torque?

“Any change in the torque being applied to the generator by the prime mover will result in a change in the amperes flowing in the generator stator. Increasing the torque above that required to maintain synchronous speed and frequency will result in amperes which can be used to power loads connected to the grid. These amperes are generally considered to "flow" out of the generator.

Decreasing the torque below that required to maintain synchronous speed and frequency will result in amperes flowing in the generator stator which will cause the generator to become a motor and keep the rotor and the prime mover turning at synchronous speed and frequency. In this case, the amperes are considered to "flow" into the generator, "motorizing" the generator.”
 
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